The desirability of taking downhole formation fluid samples for chemical and physical analysis has long been recognized by oil companies, and such sampling has been performed by the assignee of the present invention, Schlumberger, for many years. Samples of formation fluid, also known as reservoir fluid, are typically collected as early as possible in the life of a reservoir for analysis at the surface and, more particularly, in specialized laboratories. The information that such analysis provides is vital in the planning and development of hydrocarbon reservoirs, as well as in the assessment of a reservoir's capacity and performance.
The process of wellbore sampling involves the lowering of a downhole sampling tool, such as the MDT® wireline formation testing tool, owned and provided by Schlumberger, into the wellbore to collect a sample (or multiple samples) of formation fluid by engagement between a probe member of the sampling tool and the wall of the wellbore. The sampling tool creates a pressure differential across such engagement to induce formation fluid flow into one or more sample chambers within the sampling tool. This and similar processes are described in U.S. Pat. Nos. 4,860,581; 4,936,139 (both assigned to Schlumberger); U.S. Pat. Nos. 5,303,775; 5,377,755 (both assigned to Western Atlas); and U.S. Pat. No. 5,934,374 (assigned to Halliburton).
Various challenges may arise in the process of obtaining samples of fluid from subsurface formations. Again with reference to the petroleum-related industries, for example, the earth around the borehole from which fluid samples are sought typically contains contaminates, such as filtrate from the mud utilized in drilling the borehole. This material often contaminates the clean or “virgin” fluid contained in the subterranean formation as it is removed from the earth, resulting in fluid that is generally unacceptable for hydrocarbon fluid sampling and/or evaluation. As fluid is drawn into the downhole tool, contaminants from the drilling process and/or surrounding wellbore sometimes enter the tool with fluid from the surrounding formation.
To conduct valid fluid analysis of the formation, the fluid sampled preferably possesses sufficient purity to adequately represent the fluid contained in the formation (ie. “virgin” fluid). In other words, the fluid preferably has a minimal amount of contamination to be sufficiently or acceptably representative of a given formation for valid hydrocarbon sampling and/or evaluation. Because fluid is sampled through the borehole, mudcake, cement and/or other layers, it is difficult to avoid contamination of the fluid sample as it flows from the formation and into a downhole tool during sampling.
Various methods and devices have been proposed for obtaining subsurface fluids for sampling and evaluation. For example, U.S. Pat. No. 6,230,557 to Ciglenec et al., U.S. Pat. No. 6,223,822 to Jones, U.S. Pat. No. 4,416,152 to Wilson, U.S. Pat. No. 3,611,799 to Davis and International Pat. App. Pub. No. WO 96/30628 have developed certain probes and related techniques to improve sampling. Other techniques have been developed to separate virgin fluids during sampling. For example, U.S. Pat. No. 6,301,959 to Hrametz et al. and discloses a sampling probe with two hydraulic lines to recover formation fluids from two zones in the borehole. Borehole fluids are drawn into a guard zone separate from fluids drawn into a guard zone. In the published international application WO 03/100219 A1 there are disclosed sampling devices using inner and outer probes with a varying ratio of flow area.
Despite such advances in sampling, there remains a need to develop techniques for fluid sampling optimized for heavy oils and bitumens. The high viscosity of such hydrocarbon fluids often presents significant challenges for sampling representative fluids. Effective in-situ reduction of the viscosity of heavy oils without inducing phase and/or compositional changes is thus necessary to obtain a representative sample.
The reduction in the viscosity of heavy oil and bitumen for the purposes of increasing the recovery factor of a reservoir has been a topic of interest in the oil industry for many years. Several methods for the viscosity reduction are known and employed in the field today. It has long been established that heating of heavy oils and bitumens significantly reduce the fluid viscosity and subsequently, increases the fluid mobility. Small thermal changes can result in a relatively large drop in the viscosity of the oil. For example, it is known from AOSTRA Technical Report #2, The Thermodynamic and Transport Properties of Bitumens and Heavy Oils, Alberta Oil Sands Technology and Research Authority, July 1984, that the viscosity of typical Athabasca bitumen from Canada can be reduced by two orders of magnitude by increasing the temperature from 50° C. to 100° C. The plot of FIG. 1 is based on the AOSTRA report. Such a lowering in viscosity will allow for increased mobility of the viscous oil or bitumen required for sampling.
There are many literature examples, both tried and tested along with conceptual, of ways to heat in situ viscous oil in a reservoir to aid recovery. As described below in greater details with reference to examples of known recovery-enhancing techniques, these techniques are generally not immediately suitable for sampling.
Currently, the primary thermal method for heavy oil recovery is steam assisted gravity drainage (SAG-D). This process uses the injection of super-heated steam to improve the mobility of the oil. The process mainly relies on the conduction of heat from the steam to the oil. Efficient transfer of the heat requires intimate mixing of the oil and steam. During the exchange of heat, portions of the steam will be converted to liquid water, often in the form of millimeter or micron sized water droplets suspended in the oil. While it depends on the source of the oil, this process normally results in the formation of stable water-in-oil emulsion. Samples of emulsion containing oils cannot be characterized in a laboratory environment without removal of the emulsion and most demulsification protocols result in irreversible and undesirable changes to the chemical composition of the oil.
An alternative method of reducing the viscosity of the oil has been to use solvents or gases to dilute the oil and thus, form a mixture that has a lower viscosity. Depending on concentration, the dilution of the oil can cause the precipitation of the higher order species from the mixture that can also aid viscosity reduction. However, this method of viscosity reduction for sampling results in an undesirable change in the composition of the oil that prevents proper characterization of the oils chemical and physical properties.
Methods for in situ heating of oils that will not alter their composition are limited. They can be divided into two categories, Joule (or Ohmic) heating and electromagnetic heating. Ohmic heating relies on the principle of applying an electric current through a resistive element to generate heat. A recent U.S. published patent application, US 2005/0006097 A1, discloses a potential method using a downhole heater whereby variable frequencies could be applied across the resistor in order to modulate and control the heating. This method requires good placement of the heating element within the formation as conduction has to be optimized.
Electromagnetic heating uses high frequency radiation to penetrate the reservoir and heat the formation. Many examples of this type of technology for the recovery of heavy oils have been reported. Abernethy, in: Abernethy, E. R., ‘Production increase of heavy oils by electromagnetic heating’, Journal of Canadian Petroleum Technology, 1976, 91, has developed a steady state model that indicates the depth of penetration of the radiation and its heating potential for the oil. This parameter is then used to determine the viscosity reduction in the oil and the subsequent improvement in the mobility. Although the model may be quite crude, it does appear to indicate that many forms of electromagnetic heating may be used to locally heat oil for the purposes of sampling. Fanchi in: Fanchi, J. R., ‘Feasibility of reservoir heating by electromagnetic radiation’, SPE 20438, 1990, 189, devised an algorithm for determining temperature increase of an oil as a result of electromagnetic heating and also describes attempted field implementation of some of these devices.
The use of microwaves and radio frequencies for the heating of in place oil has been extensively studied. Most of the microwave work has been carried out using standard microwave frequencies of 2.45 GHz with variable power input. An evaluation of microwave heating for the heavy oil recovery published as Brealy, N., ‘Evaluation of microwave methods for UKCS heavy oil recovery’, SHARP IOR newsletter, 2004, 7, indicates that field wide application of this technology may not be economic.
In U.S. Pat. No. 5,082,054 to Kiamanesh there is disclosed a system for reservoir heating that uses tunable microwaves for oil recovery. The data indicates that this process can lead to cracking of the oil and several of the claims made support this observation. This type of heating technology has been used in a field environment for differing viscosities of oil as reported in: Ovalles, C., Fonseca, A., Lara, A., Alvarado, V., Urrechega, K., Ranson, A., and Mendoza, H., ‘Opportunities of downhole dielectric heating in Venezuela: Three case studies involving medium, heavy and extra heavy crude oil reservoirs’, SPE 78980, 2002. The oil types were medium, heavy and extra heavy and all types responded with increased mobility after irradiation. No mention was made to the composition of these oils and changes induced by the heating process.
Radio frequency heating has been applied to reservoirs containing heavy oils as described in: Kasevich, R. S., Price, S. L., Faust, D. L. and Fontaine, M. F., ‘Pilot testing of a radio frequency heating system for enhanced oil recovery from diatomaceous earth’, SPE 28619, 1994, and also to aid bitumen recovery from the tar sands. These reports indicate that a positive response, regarding the mobility of the oil, was observed due to irradiation at around 13 MHz. In the first case, 250 Kwatts of power was delivered efficiently in this manner.
In all the above cases, no mention was made regarding the changes in composition of the oil except when upgrading had occurred. High temperatures and irradiation can cause fragmentation and isomerisation of components of the oil. Studies on plant oils have shown unsaturation and heteroatoms are affected by prolonged exposure to microwave sources. This is possibly due to local heating or hot spots within the oil.
The use of heat as a way to improve the characterization of the formation has been proposed in the published US patent application no. 2004/0188140 to S. Chen and D. T. Georgi. The described method proposes the heating the oil to increase the T2 relaxation time of the system. This results in more accurate NMR measurements. No information on the monitoring and control of this process are given.
In the light of the described prior art, which to the extend as it refers to heating methods for and properties of heavy oil is incorporated herein, it remains the need to develop apparatus and methods for the reservoir sampling of reservoir with heavy oil or bitumen content.